Wellbores are drilled at wellsites to locate and produce hydrocarbons. A downhole drilling tool with a bit at an end thereof is advanced into the ground to form a wellbore. As the drilling tool is advanced, a drilling mud is pumped from a surface mud pit, through the drilling tool and out the drill bit to cool the drilling tool and carry away cuttings. The fluid exits the drill bit and flows back up to the surface for recirculation through the tool. The drilling mud is also used to form a mudcake to line the wellbore.
FIG. 1 illustrates a wellsite system 1 which includes a surface system 2, a downhole system 3 and a surface control unit 4. In the illustrated embodiment, a borehole 11 is formed by rotary drilling in a manner that is well known.
The downhole system 3 includes a drill string 12 suspended within the borehole 11 with a drill bit 15 at its lower end. The surface system 2 includes the land-based platform and derrick assembly 10 positioned over the borehole 11 penetrating a subsurface formation F. The assembly 10 includes a rotary table 16, kelly 17, hook 18 and rotary swivel 19. The drill string 12 is rotated by the rotary table 16, energized by means not shown, which engages the kelly 17 at the upper end of the drill string. The drill string 12 is suspended from a hook 18, attached to a traveling block (also not shown), through the kelly 17 and a rotary swivel 19 which permits rotation of the drill string relative to the hook.
The surface system further includes drilling fluid or mud 26 stored in a pit 27 formed at the well site. A pump 29 delivers the drilling fluid 26 to the interior of the drill string 12 via a port in the swivel 19, inducing the drilling fluid to flow downwardly through the drill string 12 as indicated by the directional arrow 9. The drilling fluid exits the drill string 12 via ports in the drill bit 15, and then circulates upwardly through the region between the outside of the drill string and the wall of the borehole, called the annulus, as indicated by the directional arrows 32. In this manner, the drilling fluid lubricates the drill bit 15 and carries formation cuttings up to the surface as it is returned to the pit 27 for recirculation.
The drill string 12 further includes a bottom hole assembly (BHA), generally referred to as 100, near the drill bit 15 (in other words, within several drill collar lengths from the drill bit). The bottom hole assembly includes capabilities for measuring, processing, and storing information, as well as communicating with the surface. The BHA 100 thus includes, among other things, an apparatus 110 for determining and communicating one or more properties of the formation F surrounding borehole 11, such as formation resistivity (or conductivity), natural radiation, density (gamma ray or neutron), and pore pressure.
The BHA 100 further includes drill collars 130, 150 for performing various other measurement functions. Drill collar 150 houses a measurement-while-drilling (MWD) tool. The MWD tool further includes an apparatus 160 for generating electrical power to the downhole system. While a mud pulse system is depicted with a generator powered by the flow of the drilling fluid 26 that flows through the drill string 12 and the MWD drill collar 150, other power and/or battery systems may be employed.
Sensors are located about the wellsite to collect data, preferably in real time, concerning the operation of the wellsite, as well as conditions at the wellsite. For example, monitors, such as cameras 6, may be provided to provide pictures of the operation. Surface sensors or gauges 7 are disposed about the surface systems to provide information about the surface unit, such as standpipe pressure, hookload, depth, surface torque, rotary rpm, among others. Downhole sensors or gauges 8 are disposed about the drilling tool and/or wellbore to provide information about downhole conditions, such as wellbore pressure, weight on bit, torque on bit, direction, inclination, collar rpm, tool temperature, annular temperature and toolface, among others. The information collected by the sensors and cameras is conveyed to the surface system, the downhole system and/or the surface control unit.
The MWD tool 150 includes a communication subassembly 152 that communicates with the surface system. The communication subassembly 152 is adapted to send signals to and receive signals from the surface using mud pulse telemetry. The communication subassembly may include, for example, a transmitter that generates a signal, such as an acoustic or electromagnetic signal, which is representative of the measured drilling parameters. The generated signal is received at the surface by transducers, represented by reference numeral 31, that convert the received acoustical signals to electronic signals for further processing, storage, encryption and use according to conventional methods and systems. Communication between the downhole and surface systems is depicted as being mud pulse telemetry, such as the one described in U.S. Pat. No. 5,517,464, assigned to the assignee of the present invention. It will be appreciated by one of skill in the art that a variety of telemetry systems may be employed, such as wired drill pipe, electromagnetic or other known telemetry systems.
Downhole tools, such as those in BHA 100, are subjected to high shock and extreme vibration intrinsic to the drilling process. These high shock and vibration loads can significantly reduce the efficiency, accuracy and reliability of the tools. Shock and vibration may be of particular concern when the tools carry delicate and sensitive electronics equipment, such as the measuring and communications assemblies described above. MWD tools and their associated sensors may, for example, especially susceptible to damage and inaccurate performance in high shock and vibration environments.
The borehole depicted in FIG. 1 is oriented vertically in a downward direction from ground level as is typical at a wellsite. Boreholes are, however, often required to be formed in a diagonal, horizontal or upward direction with respect to the drilling surface. Despite the orientation, the drilling tools are typically subjected to significant shock and vibration. Those of ordinary skill in the art, given the benefit of this disclosure, will appreciate that the present invention also finds application in drilling applications other than conventional wellsites as illustrated in FIG. 1 and this invention is not limited thereto.
The industry has attempted to address the adverse effects of shock and vibration on downhole tools in a number of ways, such as the use of specially designed drill collars to protect the delicate components in the drilling tools. While such collars provide a measure of protection against shock and vibration, they are often expensive to make, to deploy in the borehole and to maintain. Moreover, the special design and expense of these protective collars can limit their use at other locations in the drill string.
Drill collars primarily are designed to provide structure to the drill string and to serve as a passageway for the drilling tools and drilling mud into the borehole as illustrated in FIG. 1. Drill collars are a required fixture at most drill sites and come in various lengths and diameters. It is not uncommon for a wellsite to require several hundred drill collars in order to complete the borehole to the required depth.
Thus, the industry has developed manufacturing techniques and economies for making drill collars for their conventional and passive purposes relatively inexpensively. When drill collars must also perform an active function, such as protecting drilling tools from the harmful effects of shock and vibration from the drilling operation, the special design and materials required for these purposes greatly increases the cost of the drill collar and discourages their use for more conventional purposes.
Some protective drill collars have been used in an attempt to limit the internal displacement of the various tool components within the collar. The tool components are typically installed inside the protective collar and physically attached to its interior. While this approach may provide a measure of protection, the protective collar and the tool components are typically very expensive and often cannot be retrieved if stuck. Thus, while some degree of protection may be achieved, the costs of such a protective collar and its tool components can be very expensive. The risk of such a financial loss often deters the use of protective collars for expensive tool components, such as MWDs. Even in cases where retrievability is possible by providing a protective collar, the impact on the cost to operate the service can become prohibitive in many situations.
Various techniques have been developed for protecting various downhole components within drilling tools. See, for example, U.S. Pat. Nos. 6,761,230; 4,265,305 and 4,537,067. Some such techniques involve the use of centralizers or rings positioned within the drill collar to protect internal components.
Despite the development and advancement of various approaches to protecting downhole components within drill collars or other housings of downhole tools, there remains a need to provide such protection in a more economical manner. It is desirable that a protection system be provided that permits the retrievable of the downhole components should the downhole tool become stuck in the borehole. It is further desirable that such a protection system not require the use of specially designed and/or expensive drilling collar. Preferably, such as protection system provides one or more of the following, among others: retrievability of the downhole components reduced manufacturing costs, reduced maintenance costs, enhanced component protection, reduced shock and/or vibration.